The present disclosure relates to subterranean formation operations and, more particularly, to a running fluid for use in running a tubular into a subterranean formation.
Wellbores are often drilled into subterranean formations (or simply “formation”) to recover hydrocarbons (e.g., oil and/or gas) therefrom. In constructing such wellbores and preparing them for hydrocarbon recovery, it is often necessary to run a tubular into the wellbore (e.g., in preparation of a cementing operation). Such tubulars are frequently referred to as casing or liner string, and encompasses any conduit including pipe, tubing, coiled tubing, and the like. The tubulars are run into the subterranean formation with a running fluid in the formation.
Challenges encountered during running such tubulars include effectively managing wellbore pressure, as the wellbore is exposed to surge and swab pressures during the running. Specifically, the running contributes to pressures in the wellbore that can be expressed in terms of equivalent circulating density (ECD), which are additional pressures exerted on the formation that can induce fractures, lost circulation, or collapse of the tubular. Tubular running must also be performed while avoiding increased surge pressures and slow tubular-running speeds, and avoiding sag of any additives (e.g., weighting agents, and the like) included in the running fluid. As used herein, the term “sag” refers to the settling of particulates in the annulus of a wellbore from a static or circulated fluid. Additionally, if the tubular is run in preparation for a cementing operation, induced fractures may cause the wellbore to take on losses, reducing the likelihood of achieving a quality cementing operation as the height allowance for the pumped cement may be reduced. Accordingly, ECD management is critical to ensure that the pressure within the wellbore during tubular running stays within the pore pressure and fracture gradient pressure window. As used herein, the term “fracture gradient pressure” or “fracture gradient” refers to the pressure required to induce fractures in a subterranean formation at a given depth.
Particular wellbore configurations or formation compositions may pose greater challenges than others. For example, depleted zones in a formation may pose an ECD challenge as well as a lost circulation hazard because of the regression of the pore pressure and the fracture gradient compared with the surrounding formation strata. Additionally, depleted zones may pose a stuck pipe hazard due to overbalanced densities of surrounding running fluids, resulting in extreme differential pressures in relation to the depleted zone pressure. As another example, highly deviated wells (i.e., wellbores drilled at high-angles) may result in poor wellbore cleaning, which adversely affects ECD. For instance, in deviated wells having deviated angles of greater than about 30°, cutting beds may form due to an insufficient pump rate, leading to excessive ECD, pack-offs, and/or stuck pipe. Furthermore, highly deviated wells increase the likelihood (present in all wellbores) of sag (e.g., barite sag) from the running fluid. Such sag may result in density differentials in the running fluid and, thus, in the fluid column in the wellbore, which may cause significant differences in pressure exerted on the formation. The resultant fluctuations in pressure may increase the potential for fracturing the formation, as well as inducing an influx of formation fluid.